When drilling a well, whether it be through the use of overbalanced, balanced or underbalanced drilling techniques, pressurized drilling fluid returns must be extracted from the well and treated for purposes of separating, recycling, processing or otherwise disposing of the fluids and their constituent parts. Depending upon the nature of the drilling process being utilized and the geology through which the well is drilled, the drilling fluid returns may include a wide variety of solid, liquid and gas components, such as oil, water, rock particulates, natural gas and other hydrocarbon gases, etc. Regardless of the particular drilling operation, the drilling fluid returns extracted from a well can be at a relatively high pressure when compared to atmospheric conditions. The composition and pressure of the returns therefore necessitate that they be treated and separated before further use or disposal.
To date others have suggested a wide variety of different techniques and devices that may be used to treat pressurized drilling fluid returns. Such devices function to varying degrees of efficiency and, to a large extent, have their own specific advantages and disadvantages.
In spite of the various and different techniques that have been proposed for treating pressurized drilling fluid returns, prior devices and methods continue to suffer from a number of common and inherent limitations that severely effect their application, efficient operation, and cost. For example, in a closed high pressure separation system a significant problem that is commonly faced is one of erosion of parts of the system. This occurs when solid particles, in combination with gases and liquids, contact system components as they are propelled and travel through various piping and pressure vessels. The incidence and rate of erosion is accelerated by disturbances in flow patterns that may be caused by changes in flow area and direction, or through passage through valves, orifices or similar structures that cause pressure drops. Typically erosion will be most dramatic directly downstream of such a disturbance. Where high pressure drilling fluid returns are being processed and separated, erosion of piping or other structural elements can present a significant safety concern due to the potential for ruptures or failures of eroded parts. Erosion has the affect of significantly adding to the cost of a treatment system for pressurized drilling fluid returns due to the necessity for increased replacement of damaged components, and due to increased down-time when such components must be replaced.
A second limitation of presently known treatment systems concerns the inability to effectively and economically deal with high volumes of gas separated from drilling returns. In most instances separated gas returns cannot be easily stored, and are usually at a lower pressures than production or sales pipelines. For this reason the separated gases are most often sent to flare. Flaring the gas is economically wasteful and environmentally undesirable. If low pressure gas is recovered from a separator, it must be sent to a gas compression system to increase its pressure to pipeline or process pressures, thereby adding to both capital and operating expense.
To combat situations where a large volume of gas is expelled from a well (for example when drilling through high deliverability gas zones) prior art systems and devices are typically constructed with a size and capacity that far exceeds the normal daily output from the well. This practice presents yet a third significant limitation under the prior art as over sizing separation devices in such a manner adds to the capital and operating costs of land based drilling systems. In addition, the sheer size and weight of such prior art systems in many cases also severely limits their application to offshore drilling projects.
Further, prior methods of treating drilling returns often involve monitoring liquid levels upstream of the choke that feeds a primary separation vessel as a means of regulating gas flow through the system. However, where the well expels a large quantity of liquid at one time (referred to as a liquid slug) such liquid monitoring methods are typically overloaded and fail, resulting in a liquid carryover into the gas stream. In addition, once again the size of such currently used systems results in increased costs and limited application in offshore drilling.